Chesapeake Energy Corporation Reports Financial and Operational Results for the 2007 Fourth Quarter and Full Year

Posted on: Thursday, 21 February 2008, 18:00 CST

Chesapeake Energy Corporation (NYSE:CHK) today reported financial and operating results for the 2007 fourth quarter and full year. For the 2007 fourth quarter, Chesapeake generated net income available to common shareholders of $158 million ($0.33 per fully diluted common share), operating cash flow of $1.3 billion (defined as cash flow from operating activities before changes in assets and liabilities) and ebitda of $1.2 billion (defined as net income before income taxes, interest expense, and depreciation, depletion and amortization expense) on revenue of $2.1 billion and production of 204 billion cubic feet of natural gas equivalent (bcfe).

For the 2007 full year, Chesapeake generated net income available to common shareholders of $1.2 billion ($2.62 per fully diluted common share), operating cash flow of $4.6 billion and ebitda of $4.7 billion on revenue of $7.8 billion and production of 714 bcfe.

The company's 2007 fourth quarter and full year net income available to common shareholders and ebitda include various items that are typically not included in published estimates of the company's financial results by certain securities analysts. Excluding the items detailed below, Chesapeake generated adjusted net income to common shareholders in the 2007 fourth quarter of $466 million ($0.93 per fully diluted common share) and adjusted ebitda of $1.4 billion. For the 2007 full year, Chesapeake generated adjusted net income to common shareholders of $1.6 billion ($3.21 per fully diluted common share) and adjusted ebitda of $5.0 billion.

The excluded items and their effects on 2007 fourth quarter and full year reported results are detailed as follows:

an unrealized after-tax mark-to-market loss of $180 million in the fourth quarter and $257 million for the full year resulting from the company's oil and natural gas and interest rate hedging programs;

an after-tax gain of $51 million in the second quarter resulting from the sale of the company's investment in Eagle Energy Partners I, L.P.; and

a reduction of net income available to common shareholders of $128 million for the fourth quarter and full year resulting from exchanges of the company's preferred stock for common stock that reduced future preferred stock dividend payment requirements.

The excluded items do not affect the calculation of operating cash flow. A reconciliation of operating cash flow, ebitda, adjusted ebitda and adjusted net income to comparable financial measures calculated in accordance with generally accepted accounting principles is presented on pages 18-21 of this release.

Key Operational and Financial Statistics Summarized Below for the 2007 Fourth Quarter, 2007 Third Quarter, 2006 Fourth Quarter and for the Full Years 2007 and 2006

The table below summarizes Chesapeake's key results during the 2007 fourth quarter and compares them to the 2007 third quarter and the 2006 fourth quarter and also compares the 2007 full year to the 2006 full year.

Three Months Ended:

Full Year Ended:

12/31/07

9/30/07

12/31/06

12/31/07

12/31/06

Average daily production (in mmcfe)

2,219

2,026

1,653

1,957

1,585

Natural gas as % of total production

Natural gas production (in bcf)

187.8

170.3

138.8

655.0

526.5

Average realized natural gas price ($/mcf) (a)

8.11

7.41

9.03

8.14

8.76

Oil production (in mbbls)

2,735

2,680

2,217

9,882

8,654

Average realized oil price ($/bbl) (a)

72.58

69.25

59.95

67.50

59.14

Natural gas equivalent production (in bcfe)

204.2

186.4

152.1

714.3

578.4

Natural gas equivalent realized price ($/mcfe) (a)

8.43

7.76

9.11

8.40

8.86

Oil and natural gas marketing income ($/mcfe)

.09

.10

.11

.10

.09

Service operations income ($/mcfe)

.04

.06

.09

.06

.11

Production expenses ($/mcfe)

(.88

)

(.89

)

(.82

)

(.90

)

(.85

)

Production taxes ($/mcfe)

(.32

)

(.30

)

(.31

)

(.30

)

(.31

)

General and administrative costs ($/mcfe) (b)

(.29

)

(.23

)

(.22

)

(.26

)

(.19

)

Stock-based compensation ($/mcfe)

(.08

)

(.10

)

(.04

)

(.08

)

(.05

)

DD&A of oil and natural gas properties ($/mcfe)

(2.55

)

(2.57

)

(2.51

)

(2.57

)

(2.35

)

D&A of other assets ($/mcfe)

(.16

)

(.24

)

(.20

)

(.22

)

(.18

)

Interest expense ($/mcfe) (a)

(.49

)

(.52

)

(.54

)

(.51

)

(.52

)

Operating cash flow ($ in millions) (c)

1,322

1,085

1,095

4,607

4,045

Operating cash flow ($/mcfe)

6.48

5.82

7.20

6.45

6.99

Adjusted ebitda ($ in millions) (d)

1,432

1,195

1,210

5,028

4,449

Adjusted ebitda ($/mcfe)

7.01

6.41

7.96

7.04

7.69

Net income to common shareholders ($ in millions)

158

346

446

1,229

1,904

Earnings per share -- assuming dilution ($)

.33

.72

.96

2.62

4.35

Adjusted net income to common shareholders

($ in millions) (e)

466

330

418

1,563

1,575

Adjusted earnings per share -- assuming dilution ($)

.93

.69

.90

3.21

3.61

(a) includes the effects of realized gains or (losses) from hedging, but does not include the effects of unrealized gains or (losses) from hedging

(b) excludes expenses associated with non-cash stock-based compensation

(d) defined as net income before income taxes, interest expense, and depreciation, depletion and amortization expense, as adjusted to remove the effects of certain items detailed on pages 20-21

(e) defined as net income available to common shareholders, as adjusted to remove the effects of certain items detailed on pages 20-21

Average Realized Prices, Hedging Results and Hedging Positions Detailed

Average prices realized during the 2007 fourth quarter (including realized gains or losses from oil and natural gas derivatives, but excluding unrealized gains or losses on such derivatives) were $8.11 per thousand cubic feet of natural gas (mcf) and $72.58 per barrel of oil and natural gas liquids (bbl), for a realized natural gas equivalent price of $8.43 per thousand cubic feet of natural gas equivalent (mcfe). Realized gains and losses from oil and natural gas hedging activities during the 2007 fourth quarter generated a $1.73 gain per mcf and a $13.66 loss per bbl for a 2007 fourth quarter realized hedging gain of $287 million, or $1.40 per mcfe. Excluding hedging activity, Chesapeake's average realized pricing differentials to NYMEX during the 2007 fourth quarter were a negative $0.59 per mcf and a negative $4.44 per bbl.

By comparison, average prices realized during the 2006 fourth quarter (including realized gains or losses from oil and natural gas derivatives, but excluding unrealized gains or losses on such derivatives) were $9.03 per mcf and $59.95 per bbl, for a realized natural gas equivalent price of $9.11 per mcfe. Realized gains from oil and natural gas hedging activities during the 2006 fourth quarter generated a $3.14 gain per mcf and a $4.88 gain per bbl for a 2006 fourth quarter realized hedging gain of $447 million, or $2.94 per mcfe. Excluding hedging activity, Chesapeake's average realized pricing differentials to NYMEX during the 2006 fourth quarter were a negative $0.67 per mcf and a negative $5.14 per bbl.

For the 2007 full year, average prices realized (including realized gains or losses from oil and natural gas derivatives, but excluding unrealized gains or losses on such derivatives) were $8.14 per mcf and $67.50 per bbl, for a realized natural gas equivalent price of $8.40 per mcfe. Realized gains and losses from oil and natural gas hedging activities during the 2007 full year generated a $1.85 gain per mcf and a $1.14 loss per bbl for a 2007 full year realized hedging gain of $1.2 billion, or $1.68 per mcfe. Excluding hedging activity, Chesapeake's average realized pricing differentials to NYMEX during the 2007 full year were a negative $0.57 per mcf and a negative $3.67 per bbl. During 2006 and 2007, Chesapeake's oil and natural gas hedging activities generated a total realized gain of $2.5 billion.

By comparison, for the 2006 full year, average prices realized (including realized gains or losses from oil and natural gas derivatives, but excluding unrealized gains or losses on such derivatives) were $8.76 per mcf and $59.14 per bbl, for a realized natural gas equivalent price of $8.86 per mcfe. Realized gains and losses from oil and natural gas hedging activities during the 2006 full year generated a $2.41 gain per mcf and a $1.72 loss per bbl for a 2006 full year realized hedging gain of $1.3 billion, or $2.17 per mcfe. Excluding hedging activity, Chesapeake's average realized pricing differentials to NYMEX during the 2006 full year were a negative $0.89 per mcf and a negative $5.36 per bbl.

The following tables compare Chesapeake's open hedge position through swaps and collars as well as gains from lifted hedges as of February 21, 2008 to those previously announced as of November 6, 2007. Depending on changes in oil and natural gas futures markets and management's view of underlying oil and natural gas supply and demand trends, Chesapeake may either increase or decrease its hedging positions at any time in the future without notice.

Open Swap Positions as of February 21, 2008

Natural Gas

Oil

Quarter or Year

% Hedged

$ NYMEX

% Hedged

$ NYMEX

2008 Q1

8.64

73.97

2008 Q2

8.44

75.22

2008 Q3

8.60

75.11

2008 Q4

9.13

76.79

2008 Total

8.69

75.24

2009 Total

8.94

81.60

Open Natural Gas Collar Positions as of February 21, 2008

Average

Floor

Ceiling

Quarter or Year

% Hedged

$ NYMEX

2008 Q1

7.36

9.28

2008 Q2

7.50

9.68

2008 Q3

7.50

9.68

2008 Q4

7.50

9.68

2008 Total

7.41

9.40

2009 Total

8.14

10.82

Gains from Lifted Natural Gas Hedges as of February 21, 2008

Total Gain

Assuming Natural Gas Production of:

Gain

Quarter or Year

($ millions)

(bcf)

($ per mcf)

2008 Q1

156

184

0.85

2008 Q2

194

0.23

2008 Q3

205

0.20

2008 Q4

210

0.22

2008 Total

287

793

0.36

2009 Total

897

0.01

Open Swap Positions as of November 6, 2007

Natural Gas

Oil

Quarter or Year

% Hedged

$ NYMEX

% Hedged

$ NYMEX

2008 Q1

8.78

72.84

2008 Q2

8.49

72.59

2008 Q3

8.64

72.44

2008 Q4

9.16

73.48

2008 Total

8.76

72.82

2009 Total

8.87

78.81

Open Natural Gas Collar Positions as of November 6, 2007

Average

Floor

Ceiling

Quarter or Year

% Hedged

$ NYMEX

2008 Q1

7.36

9.28

2008 Q2

7.50

9.68

2008 Q3

7.50

9.68

2008 Q4

7.50

9.68

2008 Total

7.41

9.40

2009 Total

7.97

11.18

Gains from Lifted Natural Gas Hedges as of November 6, 2007

Total Gain

Assuming Natural Gas Production of:

Gain

Quarter or Year

($ millions)

(bcf)

($ per mcf)

2008 Q1

133

188

0.71

2008 Q2

194

0.20

2008 Q3

202

0.18

2008 Q4

209

0.18

2008 Total

245

793

0.31

2009 Total

897

0.01

Certain open natural gas swap positions include knockout swaps with knockout provisions at prices ranging from $5.45 to $6.50 covering 191 billion cubic feet of natural gas (bcf) in 2008 and $5.45 to $6.50 covering 214 bcf in 2009. Certain open natural gas collar positions include three-way collars that include written put options with strike prices ranging from $5.00 to $6.00 covering 11 bcf in 2008 and $5.50 to $6.00 covering 46 bcf in 2009. Also, certain open oil swap positions include cap-swaps and knockout swaps with provisions limiting the counterparty's exposure below prices ranging from $45.00 to $65.00 covering four million barrels of oil and natural gas liquids (mmbbls) in 2008 and from $52.50 to $60.00 covering seven mmbbls in 2009.

The company's updated forecasts for 2008 through 2009 are attached to this release in an Outlook dated February 21, 2008 labeled as Schedule "A", which begins on page 23. This Outlook has been changed from the Outlook dated November 6, 2007 (attached as Schedule "B", which begins on page 27) to reflect various updated information.

Company Provides Update on 2008-2009 Financial Plan

In September 2007, Chesapeake announced an enhanced financial plan designed to monetize latent balance sheet value and to fully fund its planned capital expenditures through at least 2009 without accessing public capital markets. Since then, the company has successfully implemented multiple aspects of the plan and anticipates further progress during 2008 and 2009. Chesapeake believes its planned future transactions in the asset and financial markets will allow it to monetize additional assets for approximately $3 billion by the end of 2009 that, in management's opinion, have not been adequately reflected in the company's market valuation historically.

Producing Property Monetizations and Asset Sales -- On December 31, 2007, the company monetized certain Chesapeake-operated long-lived producing assets in Kentucky and West Virginia and retained drilling rights on the properties below currently producing intervals and outside of existing producing wellbores. Chesapeake received $1.1 billion for the sale of a volumetric production payment on the Appalachian assets covering proved reserves of approximately 208 bcfe and current production of approximately 55 million cubic feet of natural gas equivalent (mmcfe) per day. For accounting purposes, the transaction was treated as a sale and the company's proved reserves were reduced accordingly. The company also plans to pursue additional monetizations of similarly mature properties in 2008 and 2009 and anticipates further proceeds of approximately $2.0 billion.

In the 2008 first quarter, the company sold non-core oil and natural gas assets in the Rocky Mountains and in the southeastern Oklahoma Woodford Shale play for proceeds of approximately $250 million. The sales involved approximately six mmcfe of daily production and 32 bcfe of proved reserves.

Midstream Partnership -- Chesapeake is currently in the process of forming a private partnership to own a non-operating interest in its midstream natural gas assets outside of Appalachia, which consist primarily of gas gathering systems and processing assets. These assets currently generate annualized cash flow from operating activities in excess of $150 million and are expected to grow substantially over at least the next three years as the company expands its gathering systems in multiple operating areas, particularly in the Fort Worth Barnett and Arkansas Fayetteville Shale plays. The company anticipates raising $1 billion in the first half of 2008 by selling a minority interest in the partnership.

Oil and Natural Gas Production Sets Record for 26th Consecutive Quarter and 18th Consecutive Year; 2007 Fourth Quarter Average Daily Production Increases 34% over the 2006 Fourth Quarter and Full Year 2007 Production Increases 23% over Full Year 2006

Daily production for the 2007 fourth quarter averaged 2.219 bcfe, an increase of 193 mmcfe, or 10%, over the 2.026 bcfe produced per day in the 2007 third quarter and an increase of 566 mmcfe, or 34%, over the 1.653 bcfe of daily production in the 2006 fourth quarter.

Chesapeake's 2007 fourth quarter production of 204.2 bcfe was comprised of 187.8 bcf (92% on a natural gas equivalent basis) and 2.74 mmbbls (8% on a natural gas equivalent basis). Chesapeake's average daily production for the quarter of 2.219 bcfe consisted of 2.041 bcf and 29,728 bbls.

The company's sequential and year-over-year growth rates for its 2007 fourth quarter natural gas production were 10% and 35%, respectively, while the company's sequential and year-over-year growth rates for its oil production were 2% and 23%, respectively. The 2007 fourth quarter was Chesapeake's 26th consecutive quarter of sequential U.S. production growth. Over these 26 quarters, Chesapeake's U.S. production has increased 467%, for an average compound quarterly growth rate of 7% and an average compound annual growth rate of 30%. Chesapeake's daily production for the 2007 full year averaged 1.957 bcfe, an increase of 372 mmcfe, or 23%, over the 1.585 bcfe of daily production for the 2006 full year.

Chesapeake's 2007 full year production of 714.3 bcfe was comprised of 655.0 bcf (92% on a natural gas equivalent basis) and 9.882 mmbbls (8% on a natural gas equivalent basis). Chesapeake's average daily production for the 2007 full year of 1.957 bcfe consisted of 1.794 bcf and 27,074 bbls. The company's growth rate for its 2007 full year natural gas production was 24% and its growth rate for 2007 full year oil production was 14%. The 2007 full year was Chesapeake's 18th consecutive year of sequential production growth.

Oil and Natural Gas Proved Reserves Reach Record Level of 10.9 Tcfe; 2007 Full Year Drilling and Acquisition Costs Average $2.08 per Mcfe; Company Adds 1.9 Tcfe for a Reserve Replacement Rate of 369%

Chesapeake began 2007 with estimated proved reserves of 8.956 trillion cubic feet of natural gas equivalent (tcfe) and ended the year with 10.879 tcfe, an increase of 1.923 tcfe, or 21%. During the year, Chesapeake replaced its 714 bcfe of production with an estimated 2.637 tcfe of new proved reserves for a reserve replacement rate of 369%. Reserve replacement through the drillbit was 2.468 tcfe, or 346% of production and 94% of the total increase (including 1.248 tcfe of positive performance revisions, of which 1.207 tcfe relate to infill drilling and increased density locations, and 97 bcfe of positive revisions resulting from oil and natural gas price increases between December 31, 2006 and December 31, 2007). Reserve replacement through the acquisition of proved reserves completed during the year was 377 bcfe, or 53% of production and 14% of the total increase. Divestments of proved reserves during the year totaled 208 bcfe for proceeds of $1.1 billion at a sales price of $5.49 per mcfe.

Chesapeake's total drilling and acquisition costs for the year were $2.08 per mcfe (excluding costs of $343 million for seismic, $1.1 billion for acquisition of unproved properties, $1.1 billion to acquire new leasehold, $254 million for capitalized interest on leasehold and unproved property and $159 million relating to tax basis step-up and asset retirement obligations, as well as positive revisions of proved reserves from higher oil and natural gas prices). Excluding these same items, Chesapeake's exploration and development costs through the drillbit were $2.13 per mcfe during the year while reserve replacement costs through acquisitions of proved reserves were $1.78 per mcfe. A complete reconciliation of finding and acquisition costs and a roll-forward of proved reserves are presented on page 16 of this release.

During 2007, Chesapeake continued the industry's most active drilling program and drilled 1,992 gross (1,695 net) operated wells and participated in another 1,679 gross (224 net) wells operated by other companies. The company's drilling success rate was 99% for company-operated wells and 97% for non-operated wells. Also during the year, Chesapeake invested $4.3 billion in operated wells (using an average of 140 operated rigs) and $0.7 billion in non-operated wells (using an average of 105 non-operated rigs).

As of December 31, 2007, Chesapeake's estimated future net cash flows from proved reserves, discounted at an annual rate of 10% before income taxes (PV-10), and after income taxes (standardized measure) were $20.6 billion and $15.0 billion, respectively, using field differential adjusted prices of $6.19 mcf (based on a NYMEX year-end price of $6.80 per mcf) and $90.58 per bbl (based on a NYMEX year-end price of $96.00 per bbl). Chesapeake's current PV-10 changes by approximately $390 million for every $0.10 per mcf change in natural gas prices and approximately $56 million for every $1.00 per bbl change in oil prices.

By comparison, the December 31, 2006 PV-10 and standardized measure of the company's proved reserves were $13.6 billion and $10.0 billion, respectively, using field differential adjusted prices of $5.41 per mcf (based on a NYMEX year-end price of $5.64 per mcf) and $56.25 per bbl (based on a NYMEX year-end price of $61.15 per bbl). A reconciliation of PV-10 and standardized measure is presented on page 22 of this release.

In addition to the PV-10 value of its proved reserves, the net book value of the company's other assets (including gathering systems, compressors, land and buildings, investments, long-term derivative instruments and other non-current assets) was $3.2 billion as of December 31, 2007 and $2.8 billion as of December 31, 2006.

Chesapeake's Leasehold and 3-D Seismic Inventories Increase to 13 Million Net Acres and 19 Million Acres; Risked Unproved Reserves in the Company's Inventory Reach 33 Tcfe While Unrisked Unproved Reserves Reach 100 Tcfe

Since 2000, Chesapeake has invested $9.4 billion in new leasehold and 3-D seismic acquisitions and now owns the largest combined inventories of onshore leasehold (13.2 million net acres) and 3-D seismic (19.2 million acres) in the U.S. On this leasehold, Chesapeake has an estimated 3.9 tcfe of proved undeveloped reserves and approximately 33 tcfe of risked unproved reserves (100 tcfe of unrisked unproved reserves). The company is currently using 145 operated drilling rigs to further develop its inventory of approximately 36,300 net drillsites, representing more than a 10-year inventory of drilling projects.

Chesapeake characterizes its drilling inventory by one of four play types: conventional gas resource, unconventional gas resource, emerging unconventional gas resource or Appalachian Basin gas resource. In these plays, Chesapeake uses a probability-weighted statistical approach to estimate the potential number of drillsites and unproved reserves associated with such drillsites. The following table summarizes Chesapeake's ownership and activity in each gas resource play type and highlights notable projects in each play.

Est.

Risked

Est.

Est. Avg.

Total

Risked

Unrisked

Current

CHK

Drilling

Net

Average

Reserves

Proved

Unproved

Daily

Operated

Net

Density

Undrilled

Well Cost

Per Well

Reserves

Production

Rig

Play Area

Acreage

(Acres)

Wells

($000

)

(bcfe)

(mmcfe)

Count

Conventional

Southern Oklahoma

345,000

120

600

3,500

2.20

849

800

3,200

200

South Texas

145,000

400

3,300

2.00

428

500

1,900

130

Mountain Front

140,000

320

100

9,000

5.00

217

300

1,100

Other Conventional

2,970,000

Various

3,900

Various

2,449

3,000

16,500

560

Conventional Sub-total

3,600,000

5,000

3,943

4,600

22,700

985

Unconventional

Fort Worth Barnett Shale

260,000

3,550

2,600

2.50

2,062

5,900

7,300

410

Fayetteville Shale (Core)

585,000

5,725

3,000

2.00

335

9,300

21,500

100

Sahara

850,000

9,000

880

0.55

1,050

3,500

4,000

180

Deep Haley

550,000

320

325

12,000

6.00

291

1,300

7,300

100

Ark-La-Tex

220,000

950

1,700

0.90

615

400

1,900

120

Granite, Atoka and Colony Washes

200,000

1,225

4,000

2.30

881

1,800

2,500

160

Other Unconventional

935,000

Various

625

Various

196

600

700

Unconventional Sub-total

3,600,000

21,400

5,430

22,800

45,200

1,100

Emerging Unconventional

Delaware Basin Shales

815,000

160

500

6,500

3.00

1,200

11,700

Deep Bossier

390,000

320

125

10,000

5.00

400

4,500

Ardmore Basin Woodford Shale

170,000

160

200

3,400

1.70

300

1,300

Alabama Shales

315,000

100

2,000

Other Emerging Unconventional

310,000

Various

125

Various

300

2,500

Emerging Unconventional Sub-total

2,000,000

1,050

2,300

22,000

Appalachia

Marcellus Shale

1,030,000

160

1,400

1,600

1.25

1,400

5,700

Lower Huron and Other

2,970,000

Various

7,450

Various

2,100

3,900

Appalachia Sub-total

4,000,000

8,850

1,402

3,500

9,600

Total

13,200,000

36,300

10,847

33,200

99,500

2,195

145

Note: Data above is pro forma for divestitures of approximately 32 bcfe of proved reserves and 37,000 net acres of leasehold post year-end 2007. The table also reflects the effects of the company's VPP transaction that reduced Appalachian production and proved reserves by 55 mmcfe per day and 208 bcfe as of December 31, 2007.

ND = Not disclosed

Management Comments

Aubrey K. McClendon, Chesapeake's Chief Executive Officer, commented, "We are pleased to report outstanding financial and operational results for the 2007 fourth quarter and full year. We are particularly proud of our success through the drillbit that enabled the company to deliver reserve and production growth well above our expectations at very attractive finding costs. In addition, our unrivalled inventory of leasehold, 3-D seismic and undrilled locations combined with our talented, motivated, hard-working and growing employee workforce should provide many more years of increases in reserves, production and net asset value per share. Finally, we are also pleased with our progress in implementing the various elements of our enhanced financial plan that should enable Chesapeake to deliver superior growth and financial returns without accessing the public capital markets for the foreseeable future."

Conference Call Information

A conference call to discuss this release has been scheduled for Friday morning, February 22, 2008, at 9:00 a.m. EST. The telephone number to access the conference call is 913-312-0822 or toll-free 888-230-5503. The passcode for the call is 4323736. We encourage those who would like to participate in the call to dial the access number between 8:50 and 8:55 a.m. EST. For those unable to participate in the conference call, a replay will be available for audio playback from noon EST on February 22, 2008, and will run through midnight EST on Friday, March 7, 2008. The number to access the conference call replay is 719-457-0820 or toll-free 888-203-1112. The passcode for the replay is 4323736. The conference call will also be webcast live on the Internet and can be accessed by going to Chesapeake's website at www.chk.com and selecting the "News & Events" section. The webcast of the conference call will be available on our website for one year.

This press release and the accompanying Outlooks include "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements give our current expectations or forecasts of future events. They include estimates of oil and natural gas reserves, expected oil and natural gas production and future expenses, projections of future oil and natural gas prices, planned capital expenditures for drilling, leasehold acquisitions and seismic data, and statements concerning anticipated cash flow and liquidity, business strategy and other plans and objectives for future operations. Disclosures concerning the fair value of derivative contracts and their estimated contribution to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility. We caution you not to place undue reliance on our forward-looking statements, which speak only as of the date of this press release, and we undertake no obligation to update this information.

Factors that could cause actual results to differ materially from expected results are described in "Risks Related to our Business" under "Risk Factors" in the Offer to Exchange attached as an exhibit to each of the two Schedules TO we filed with the Securities and Exchange Commission on October 23, 2007. These risk factors include the volatility of oil and natural gas prices; the limitations our level of indebtedness may have on our financial flexibility; our ability to compete effectively against strong independent oil and natural gas companies and majors; the availability of capital on an economic basis, including planned asset monetization transactions, to fund reserve replacement costs; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of oil and natural gas reserves and projecting future rates of production and the amount and timing of development expenditures; uncertainties in evaluating oil and natural gas reserves of acquired properties and associated potential liabilities; our ability to effectively consolidate and integrate acquired properties and operations; unsuccessful exploration and development drilling; declines in the values of our oil and natural gas properties resulting in ceiling test write-downs; lower prices realized on oil and natural gas sales and collateral required to secure hedging liabilities resulting from our commodity price risk management activities; the negative impact lower oil and natural gas prices could have on our ability to borrow; drilling and operating risks, including potential environmental liabilities; production interruptions that could adversely affect our cash flow; and pending or future litigation.

Our production forecasts are dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Although we believe the expectations and forecasts reflected in these and other forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties.

The SEC has generally permitted oil and natural gas companies, in filings made with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use the term "unproved" to describe volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC's guidelines may prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of actually being realized by the company. While we believe our calculations of unproved drillsites and estimation of unproved reserves have been appropriately risked and are reasonable, such calculations and estimates have not been reviewed by third-party engineers or appraisers.

Chesapeake Energy Corporation is the largest independent and third-largest overall producer of natural gas in the U.S. Headquartered in Oklahoma City, the company's operations are focused on exploratory and developmental drilling and corporate and property acquisitions in the Mid-Continent, Fort Worth Barnett Shale, Fayetteville Shale, Permian Basin, Delaware Basin, South Texas, Texas Gulf Coast, Ark-La-Tex and Appalachian Basin regions of the United States. The company's Internet address is www.chk.com.

CHESAPEAKE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

($ in millions, except per share and unit data)

(unaudited)

THREE MONTHS ENDED:

December 31,

2007

2006

$/mcfe

REVENUES:

Oil and natural gas sales

1,460

7.15

1,429

9.39

Oil and natural gas marketing sales

594

2.91

406

2.67

Service operations revenue

0.17

0.22

Total Revenues

2,089

10.23

1,868

12.28

OPERATING COSTS:

Production expenses

180

0.88

125

0.82

Production taxes

0.32

0.31

General and administrative expenses

0.37

0.26

Oil and natural gas marketing expenses

575

2.81

390

2.57

Service operations expense

0.13

0.12

Oil and natural gas depreciation, depletion and amortization

521

2.55

382

2.51

Depreciation and amortization of other assets

0.16

0.20

Total Operating Costs

1,475

7.22

1,033

6.79

INCOME FROM OPERATIONS

614

3.01

835

5.49

OTHER INCOME (EXPENSE):

Interest and other income

0.01

0.04

Interest expense

(128

)

(0.63

)

(81

)

(0.53

)

Total Other Income (Expense)

(125

)

(0.62

)

(75

)

(0.49

)

INCOME BEFORE INCOME TAXES

489

2.39

760

5.00

Income Tax Expense:

Current

0.04

0.03

Deferred

177

0.87

284

1.87

Total Income Tax Expense

186

0.91

289

1.90

NET INCOME

303

1.48

471

3.10

Preferred stock dividends

(17

)

(0.08

)

(25

)

(0.17

)

Loss on exchange/conversion of preferred stock

(128

)

(0.63

)

NET INCOME AVAILABLE TO COMMON SHAREHOLDERS

158

0.77

446

2.93

EARNINGS PER COMMON SHARE:

Basic

0.34

1.05

Assuming dilution

0.33

0.96

WEIGHTED AVERAGE COMMON AND COMMON

EQUIVALENT SHARES OUTSTANDING (in millions)

Basic

468

426

Assuming dilution

476

491

CHESAPEAKE ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

($ in millions, except per share and unit data)

(unaudited)

TWELVE MONTHS ENDED:

December 31,

2007

2006

$/mcfe

REVENUES:

Oil and natural gas sales

5,624

7.88

5,619

9.71

Oil and natural gas marketing sales

2,040

2.86

1,577

2.73

Service operations revenue

136

0.19

130

0.23

Total Revenues

7,800

10.93

7,326

12.67

OPERATING COSTS:

Production expenses

640

0.90

490

0.85

Production taxes

216

0.30

176

0.31

General and administrative expenses

243

0.34

139

0.24

Oil and natural gas marketing expenses

1,969

2.76

1,522

2.63

Service operations expense

0.13

0.12

Oil and natural gas depreciation, depletion and amortization

1,835

2.57

1,359

2.35

Depreciation and amortization of other assets

154

0.22

104

0.18

Employee retirement expense

0.09

Total Operating Costs

5,151

7.22

3,913

6.77

INCOME FROM OPERATIONS

2,649

3.71

3,413

5.90

OTHER INCOME (EXPENSE):

Interest and other income

0.02

0.05

Interest expense

(406

)

(0.57

)

(301

)

(0.52

)

Gain on sale of investment

0.12

117

0.20

Total Other Income (Expense)

(308

)

(0.43

)

(158

)

(0.27

)

INCOME BEFORE INCOME TAXES

2,341

3.28

3,255

5.63

Income Tax Expense:

Current

0.04

0.01

Deferred

861

1.21

1,247

2.16

Total Income Tax Expense

890

1.25

1,252

2.17

NET INCOME

1,451

2.03

2,003

3.46

Preferred stock dividends

(94

)

(0.13

)

(89

)

(0.15

)

Loss on exchange/conversion of preferred stock

(128

)

(0.18

)

(10

)

(0.02

)

NET INCOME AVAILABLE TO COMMON SHAREHOLDERS

1,229

1.72

1,904

3.29

EARNINGS PER COMMON SHARE:

Basic

2.69

4.78

Assuming dilution

2.62

4.35

WEIGHTED AVERAGE COMMON AND COMMON

EQUIVALENT SHARES OUTSTANDING (in millions)

Basic

456

398

Assuming dilution

487

459

CHESAPEAKE ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

(in millions)

(unaudited)

December 31,

2007

2006

Cash

Other current assets

1,395

1,151

Total Current Assets

1,396

1,154

Property and equipment (net)

28,337

21,904

Other assets

1,001

1,359

Total Assets

30,734

24,417

Current liabilities

2,760

1,890

Long-term debt, net

10,950

7,376

Asset retirement obligation

236

193

Other long-term liabilities

692

390

Deferred tax liability

3,966

3,317

Total Liabilities

18,604

13,166

Stockholders' Equity

12,130

11,251

Total Liabilities & Stockholders' Equity

30,734

24,417

Common Shares Outstanding

511

457

CHESAPEAKE ENERGY CORPORATION

CAPITALIZATION

(in millions)

(unaudited)

December 31,

% of Total Book

December 31,

% of Total Book

2007

Capitalization

2006

Capitalization

Long-term debt, net

10,950

7,376

Stockholders' equity

12,130

11,251

Total

23,080

100

18,627

100

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF 2007 ADDITIONS TO OIL AND NATURAL GAS PROPERTIES

($ in millions, except per unit data)

(unaudited)

Reserves

Cost

(in mmcfe)

$/mcfe

Exploration and development costs

5,055

2,371,063

(a)

2.13

Acquisition of proved properties

671

377,230

1.78

Subtotal

5,726

2,748,293

2.08

Divestitures

(1,142

)

(208,141

)

(5.49

)

Geological and geophysical costs

343

Adjusted subtotal

4,927

2,540,152

1.94

Revisions -- price

97,118

Leasehold acquisition costs

886

Lease brokerage costs and recording fees

224

Acquisition of unproved properties and other

1,101

Capitalized interest on leasehold and unproved property

254

Adjusted subtotal

7,392

2,637,270

2.80

Tax basis step-up

131

Asset retirement obligation and other

Total

7,552

2,637,270

2.86

(a) Includes 1,248 bcfe of positive performance revisions (1,207 bcfe relating to infill drilling and increased density locations and 41 bcfe of other performance related revisions) and excludes positive revisions of 97 bcfe resulting from oil and natural gas price increases between December 31, 2006 and 2007.

CHESAPEAKE ENERGY CORPORATION

ROLL-FORWARD OF PROVED RESERVES

TWELVE MONTHS ENDED DECEMBER 31, 2007

(unaudited)

Mmcfe

Beginning balance, 01/01/07

8,955,614

Extensions and discoveries

1,122,986

Acquisitions

377,230

Divestitures

(208,141

)

Revisions -- performance

1,248,077

Revisions -- price

97,118

Production

(714,261

)

Ending balance, 12/31/07

10,878,623

Reserve replacement

2,637,270

Reserve replacement ratio (a)

369

(a) The company uses the reserve replacement ratio as an indicator of the company's ability to replenish annual production volumes and grow its reserves, thereby providing some information on the sources of future production. It should be noted that the reserve replacement ratio is a statistical indicator that has limitations. The ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not embed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation.

CHESAPEAKE ENERGY CORPORATION

SUPPLEMENTAL DATA -- OIL AND NATURAL GAS SALES AND INTEREST EXPENSE

(unaudited)

THREE MONTHS ENDED

TWELVE MONTHS ENDED

December 31,

2007

2006

2007

2006

Oil and Natural Gas Sales ($ in millions):

Oil sales

236

122

678

527

Oil derivatives -- realized gains (losses)

(38

)

(11

)

(15

)

Oil derivatives -- unrealized gains (losses)

(180

)

(235

)

Total Oil Sales

137

432

540

Natural gas sales

1,199

817

4,117

3,343

Natural gas derivatives -- realized gains (losses)

324

436

1,214

1,269

Natural gas derivatives -- unrealized gains (losses)

(81

)

(139

)

467

Total Natural Gas Sales

1,442

1,292

5,192

5,079

Total Oil and Natural Gas Sales

1,460

1,429

5,624

5,619

Average Sales Price -- excluding gains (losses) on derivatives:

Oil ($ per bbl)

86.24

55.07

68.64

60.86

Natural gas ($ per mcf)

6.38

5.89

6.29

6.35

Natural gas equivalent ($ per mcfe)

7.03

6.17

6.71

6.69

Average Sales Price -- excluding unrealized gains (losses)

on derivatives):

Oil ($ per bbl)

72.58

59.95

67.50

59.14

Natural gas ($ per mcf)

8.11

9.03

8.14

8.76

Natural gas equivalent ($ per mcfe)

8.43

9.11

8.40

8.86

Interest Expense ($ in millions):

Interest

365

301

Derivatives -- realized (gains) losses

Derivatives -- unrealized (gains) losses

)

Total Interest Expense

128

406

301

CHESAPEAKE ENERGY CORPORATION

CONDENSED CONSOLIDATED CASH FLOW DATA

(in millions)

(unaudited)

THREE MONTHS ENDED:

December 31,

2007

2006

Beginning cash

Cash provided by operating activities

1,544

1,861

Cash (used in) investing activities

(1,434

)

(2,274

)

Cash provided by financing activities

(111

)

415

Ending cash

TWELVE MONTHS ENDED:

December 31,

2007

2006

Beginning cash

Cash provided by operating activities

4,932

4,843

Cash (used in) investing activities

(7,922

)

(8,942

)

Cash provided by financing activities

2,988

4,042

Ending cash

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF OPERATING CASH FLOW AND EBITDA

(in millions)

(unaudited)

THREE MONTHS ENDED:

December 31,

September 30,

December 31,

2007

2006

CASH PROVIDED BY OPERATING ACTIVITIES

1,544

1,267

1,861

Adjustments:

Changes in assets and liabilities

(222

)

(182

)

(766

)

OPERATING CASH FLOW(a)

1,322

1,085

1,095

(a) Operating cash flow represents net cash provided by operating activities before changes in assets and liabilities. Operating cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under accounting principles generally accepted in the United States (GAAP). Operating cash flow is widely accepted as a financial indicator of an oil and natural gas company's ability to generate cash which is used to internally fund exploration and development activities and to service debt. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies within the oil and natural gas exploration and production industry. Operating cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing, or financing activities as an indicator of cash flows, or as a measure of liquidity.

THREE MONTHS ENDED:

December 31,

September 30,

December 31,

2007

2006

NET INCOME

303

372

471

Income tax expense

186

228

289

Interest expense

128

116

Depreciation and amortization of other assets

Oil and natural gas depreciation, depletion and amortization

521

479

382

EBITDA(b)

1,171

1,240

1,253

(b) Ebitda represents net income before income tax expense, interest expense, and depreciation, depletion and amortization expense. Ebitda is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies. Ebitda is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders pursuant to our bank credit agreement and is used in the financial covenants in our bank credit agreement and our senior note indentures. Ebitda is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations, or cash flow provided by operating activities prepared in accordance with GAAP. Ebitda is reconciled to cash provided by operating activities as follows:

THREE MONTHS ENDED:

December 31,

September 30,

December 31,

2007

2006

CASH PROVIDED BY OPERATING ACTIVITIES

1,544

1,267

1,861

Changes in assets and liabilities

(222

)

(182

)

(766

)

Interest expense

128

116

Unrealized gains (losses) on oil and natural gas derivatives

(261

)

Other non-cash items

(18

)

EBITDA

1,171

1,240

1,253

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF OPERATING CASH FLOW AND EBITDA

(in millions)

(unaudited)

TWELVE MONTHS ENDED:

December 31,

2007

2006

2005

CASH PROVIDED BY OPERATING ACTIVITIES

4,932

4,843

2,407

Adjustments:

Changes in assets and liabilities

(325

)

(798

)

OPERATING CASH FLOW(a)

4,607

4,045

2,426

TWELVE MONTHS ENDED:

December 31,

2007

2006

2005

NET INCOME

1,451

2,003

948

Income tax expense

890

1,252

545

Interest expense

406

301

220

Depreciation and amortization of other assets

154

104

Oil and natural gas depreciation, depletion and amortization

1,835

1,359

894

EBITDA(b)

4,736

5,019

2,658

TWELVE MONTHS ENDED:

December 31,

2007

2006

2005

CASH PROVIDED BY OPERATING ACTIVITIES

4,932

4,843

2,407

Changes in assets and liabilities

(325

)

(798

)

Interest expense

406

301

220

Unrealized gains (losses) on oil and natural gas derivatives

(375

)

496

Other noncash items

177

(29

)

EBITDA

4,736

5,019

2,658

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON SHAREHOLDERS

($ in millions, except per share data)

(unaudited)

December 31,

September 30,

December 31,

THREE MONTHS ENDED:

2007

2006

Net income available to common shareholders

158

346

446

Adjustments:

Loss on conversion/exchange of preferred stock

128

Unrealized (gains) losses on derivatives, net of tax

180

(16

)

(27

)

Adjusted net income available to common shareholders1

466

330

419

Preferred dividends

Total adjusted net income

483

356

444

Weighted average fully diluted shares outstanding2

520

517

491

Adjusted earnings per share assuming dilution

0.93

0.69

0.90

1 Adjusted net income available to common and adjusted earnings per share assuming dilution exclude certain items that management believes affect the comparability of operating results. The company discloses these non-GAAP financial measures as a useful adjunct to GAAP earnings because:

a. Management uses adjusted net income available to common to evaluate the company's operational trends and performance relative to other oil and natural gas producing companies.

b. Adjusted net income available to common is more comparable to earnings estimates provided by securities analysts.

c. Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items.

2 Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADJUSTED EBITDA

($ in millions)

(unaudited)

December 31,

September 30,

December 31,

THREE MONTHS ENDED:

2007

2006

EBITDA

1,171

1,240

1,253

Adjustments, before tax:

Unrealized (gains) losses on oil and natural gas derivatives

261

(45

)

(43

)

Adjusted ebitda1

1,432

1,195

1,210

1 Adjusted ebitda excludes certain items that management believes affect the comparability of operating results. The company discloses these non-GAAP financial measures as a useful adjunct to ebitda because:

a. Management uses adjusted ebitda to evaluate the company's operational trends and performance relative to other oil and natural gas producing companies.

b. Adjusted ebitda is more comparable to estimates provided by securities analysts.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON SHAREHOLDERS

($ in millions, except per share data)

(unaudited)

December 31,

TWELVE MONTHS ENDED:

2007

2006

2005

Net income available to common shareholders

1,229

1,904

880

Adjustments:

Loss on conversion/exchange of preferred stock

128

Unrealized (gains) losses on derivatives, net of tax

257

(308

)

(27

)

Gain on sale of investment, net of tax

(51

)

(73

)

Employee retirement expense, net of tax

Cumulative impact of income tax rate change

Loss on repurchases or exchanges of senior notes, net of tax

Reversal of severance tax accrual, net of tax

)

Adjusted net income available to common shareholders1

1,563

1,575

924

Preferred dividends

Total adjusted net income

1,657

1,664

966

Weighted average fully diluted shares outstanding2

517

461

375

Adjusted earnings per share assuming dilution

3.21

3.61

2.57

a. Management uses adjusted net income available to common to evaluate the company's operational trends and performance relative to other oil and natural gas producing companies.

b. Adjusted net income available to common is more comparable to earnings estimates provided by securities analysts.

2 Weighted average fully diluted shares outstanding include shares that were considered antidilutive for calculating earnings per share in accordance with GAAP.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF ADJUSTED EBITDA

($ in millions)

(unaudited)

December 31,

TWELVE MONTHS ENDED:

2007

2006

2005

EBITDA

4,736

5,019

2,658

Adjustments, before tax:

Unrealized (gains) losses on oil and natural gas derivatives

375

(496

)

(41

)

Reversal of severance tax accrual

(12

)

Gain on sale of investment

(83

)

(117

)

Employee retirement expense

Loss on repurchase or exchange of senior notes

Adjusted EBITDA1

5,028

4,449

2,687

1 Adjusted EBITDA excludes certain items that management believes affect the comparability of operating results. The company discloses these non-GAAP financial measures as a useful adjunct to EBITDA because:

a. Management uses adjusted EBITDA to evaluate the company's operational trends and performance relative to other oil and natural gas producing companies.

b. Adjusted EBITDA is more comparable to earnings estimates provided by securities analysts.

c. Items excluded generally are one-time items, or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items.

CHESAPEAKE ENERGY CORPORATION

RECONCILIATION OF PV-10

($ in millions)

(unaudited)

December 31,

2007

December 31,

2006

Standardized measure of discounted future net cash flows

14,962

10,007

Discounted future cash flows for income taxes

5,611

3,640

Discounted future net cash flows before income taxes (PV-10)

20,573

13,647

PV-10 is discounted (at 10%) future net cash flows before income taxes. The standardized measure of discounted future net cash flows includes the effects of estimated future income tax expenses and is calculated in accordance with SFAS 69. Management uses PV-10 as one measure of the value of the company's current proved reserves and to compare relative values among peer companies without regard to income taxes. We also understand that securities analysts and rating agencies use this measure in similar ways. While PV-10 is based on prices, costs and discount factors which are consistent from company to company, the standardized measure is dependent on the unique tax situation of each individual company.

The company's December 31, 2007 PV-10 and standardized measure were calculated using field differential adjusted prices of $6.19 mcf (based on a NYMEX year-end price of $6.80 per mcf) and $90.58 per bbl (based on a NYMEX year-end price of $96.00 per bbl). The company's December 31, 2006 PV-10 and standardized measure were calculated using field differential adjusted prices of $5.41 per mcf (based on a NYMEX year-end price of $5.64 per mcf) and $56.25 per bbl (based on a NYMEX year-end price of $61.15 per bbl).

SCHEDULE "A"

CHESAPEAKE'S OUTLOOK AS OF FEBRUARY 21, 2008

Quarter Ending March 31, 2008 and Years Ending December 31, 2008 and 2009.

We have adopted a policy of periodically providing guidance on certain factors that affect our future financial performance. As of February 21, 2008, we are using the following key assumptions in our projections for the first quarter of 2008 and the full years 2008 and 2009.

The primary changes from our November 6, 2007 Outlook are in italicized bold and are explained as follows:

1) We are providing our first guidance for th

Source: Business Wire

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Chesapeake Energy Corporation Reports Financial and Operational Results for the 2007 Fourth Quarter and Full Year

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